Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming, and ultimately very expensive endeavors. As a result, over the years, a tremendous amount of added emphasis has been placed on monitoring and maintaining wells throughout their productive lives. Well monitoring and maintenance may be directed at maximizing production as well as extending well life. In the case of well monitoring, logging and other applications may be utilized which provide temperature, pressure and other production related information. In the case of well maintenance, a host of interventional applications may come into play. For example, perforations may be induced in the wall of the well, regions of the well closed off, debris or tools and equipment removed that have become stuck downhole, etc. Additionally, in some cases the well may be repaired or treated by the introduction of downhole treatment fluids such as cement for plugging a region of the well or perforations thereof.
With respect to the delivery of downhole treatment fluid, several thousand feet of coiled tubing or other tubular equipment may be brought to the well site at an oilfield. This may be achieved by appropriate positioning of a coiled tubing reel near the well, for example with a coiled tubing truck and delivery equipment. Generally, a downhole end of the coiled tubing may be preloaded with the treatment fluid whereas a more inert driving fluid such as water is located immediately uphole of the treatment fluid. A spot valve may be located at the downhole end of the coiled tubing so as to help ensure that the loaded fluids do not prematurely leak back out of the downhole end of the coiled tubing.
The loaded coiled tubing may be deployed from the reel at the surface of the oilfield and into the well. With the downhole end of the coiled tubing being first to reach the region of the well for treatment, advancement of the coiled tubing may be stopped. In theory, pressure within the coiled tubing may then be driven up by a surface pump in order to overcome the retaining capacity of the spot valve. Thus, the treatment fluid may be delivered to the noted well region.
Unfortunately, while a conventional spot valve is particularly adept at ensuring proper filling of the downhole end of the coiled tubing with the noted treatment fluids, it is generally limited in the amount of fluid pressure which it may ultimately retain. For example, a conventional spot valve may be rated to sufficiently hold back about 500 psi in the downhole end of the coiled tubing. This may be more than enough capacity to hold back a column of cement for a standard cementing treatment application. However, as noted above, the coiled tubing is loaded with treatment fluid in the downhole end with an additional driving fluid occupying the coiled tubing immediately above the treatment fluid. Thus, the spot valve is ultimately relied upon to hold back the treatment fluid as well as perhaps several thousand additional columnar feet of driving fluid upon full deployment of the coiled tubing. Thus, depending on the differential pressure between the well and the column of fluid in the coiled tubing, the likelihood of the spot valve failing may be quite significant.
Considering the ever increasing well depths and corresponding larger fluid columns of the coiled tubing, the likelihood of premature spot valve failure is quite significant, particularly where low bottom hole pressure wells are concerned. For example, where the treatment region of the well is located 15,000 to 20,000 feet below surface, the ability of a 500 psi rated spot valve to hold back a fluid column of such a depth is highly dependent upon the surrounding pressure in the well. That is, pressure at the interior of the spot valve is likely to be close to say about 2,000 psi in such a circumstance. Thus, so long as the pressure in the well remains above 1,500 psi, premature leaking of the spot valve may be avoided. In a low bottom hole pressure well, however, say a 1,000 psi well in the present spot valve example, the differential pressure would be insufficient to prevent failure of the valve. Rather, the spot valve would fail uphole of the treatment region, once 1,500 psi had built up interior thereof (e.g. overcoming the 500 psi of the spot valve plus the 1,000 psi of well pressure).
Such a failure of the spot valve as noted may have extremely negative consequences which go beyond the mere time lost in running an ineffective fluid treatment application. For example, release of a treatment fluid such as cement uphole of the targeted region may leave productive well regions contaminated or clogged with cement. Thus, in addition to re-running the application, additional time may be lost in first cleaning out the unintentionally cemented areas of the well. Ultimately, premature failure of the spot valve may cost up to a day or more of lost time at a cost of potentially several hundred thousand dollars.
Given the potential consequences of premature spot valve failure, attempts have been made to load the coiled tubing with treatment fluid from surface only once the coiled tubing reaches the targeted well region. In theory this would avoid the possibility of valve failure and premature treatment fluid delivery. Unfortunately, this means that a harsh treatment fluid such as cement needs to be pumped through several thousand feet of narrow coiled tubing. This adds a significant amount of time to the application and raises the possibility of the treatment fluid becoming contaminated with driving fluid. Thus, even in the case of low bottom hole pressure wells, the technique of preloading the downhole end of the coiled tubing with treatment fluid and hoping for the best out of the spot valve is generally considered the most practical option available to the operator.